In-line flow separation of fluids in a pipe separator

ABSTRACT

An in-line flow separator comprises an uphill section of pipeline which, in use, carries a gravitationally stratified flow of a first liquid and a second denser liquid. The second liquid forms a sump extending uphill from the foot of the uphill section, and an interface between the first and second liquids on the uphill section is inclined from the horizontal. An extraction port in the pipeline extracts the second liquid from the sump.

CROSS REFERENCE TO RELATED APPLICATIONS

This patent application is a divisional application from U.S. patentapplication Ser. No. 11/718,937 filed Apr. 25, 2008 entitled “IN-LINEFLOW SEPARATION OF FLUIDS IN A PIPE SEPARATOR” which is a 371application from PCT/EP2005/011138, entitled “IN-LINE FLOW SEPARATION OFFLUIDS IN A PIPE SEPARATOR” filed under the PCT on Oct. 17, 2005; whichclaims priority to UK application number 0425167.4, entitled “ANINCLINED FLUID SEPARATION SYSTEM” filed in the United Kingdom on Nov.15, 2004, now United Kingdom Patent No. 2 420 132 which is incorporatedby reference herein in its entirety.

FIELD OF THE INVENTION

The present invention relates to in-line flow separation, andparticularly, but not exclusively, to in-line flow separation on oilpipelines.

BACKGROUND OF THE INVENTION

Oil pipelines, particularly those extending from wellheads, typicallycarry a mixture of oil and water, and often significant amounts of gas.

Removal of the water from the oil is desirable, and many types ofseparators are known in the art.

In particular, gravity separators, which rely on the higher density ofwater than oil for separation of the phases, are commonly used. In aconventional gravity separator, separation is usually achieved byallowing the fluid phases to have a few minutes of stagnant retentiontime under the influence of gravity alone. Retention time on the orderof minutes necessitates large and bulky vessels to achieve separationbetween the liquid phases.

The most common type of water separator is a large tank separator.However, tank separators are bulky and present operational difficultiese.g. for offshore operation due to limits on available space.Furthermore, tank separators, being bulky, are typically provided ascentralised facilities accepting co-mingled production from a number ofpipelines. However, this means that the production pipelines whichsupply such separators (sometimes over long distances) are oftenoverloaded with water and therefore larger and more costly than theyneed to be.

U.S. Pat. No. 5,837,152 discloses a gravity tank separator in which thetank is formed as an elongate cylinder disposed obliquely to thehorizontal.

Several alternatives have been suggested to replace the dependence onconventional gravity tank separation, of which cyclonic separation andin-line separation have received considerable attention recently.Cyclonic in-line separation has been applied successfully to mixtures oftwo phases with highly contrasting densities, such as the case indegassing and deliquidising. In-line separation of two liquids ofrelatively comparable densities has also been demonstrated successfully.This latter technology offers significant advantages over conventionaltank gravity separation, such as reduction in equipment size, separationwhile liquid is being transported, and improved emulsion breaking.However, the separation is still effectively based on gravitationalsettling of stagnantly retained liquids.

U.S. Pat. No. 6,755,978 discloses an apparatus for separating a firstfluid from a mixture of a first and a second fluid. The apparatus has asettling chamber surrounding a production pipe for the flowing mixture.At least one aperture allows the mixture to flow into the settlingchamber from the production pipe.

U.S. Pat. No. 6,719,048 discloses an apparatus for the downholeseparation of water from the oil/gas in a well. Gravity is allowed towork on a non-vertical section of the well to separate fluid components,and the separated components are then pumped to the surface or into asubterranean discharge zone using separated flow paths. Detectors areused to control the pumping to keep unsettled/unseparated mixture awayfrom the separated flow paths.

WO 02/01044 proposes an inclined separator for separating well fluids.The separator has an inlet which comprises insert tubes for well fluids,and at least two outlets for discharge of the separated fluids. Theinsert tubes extend from one of the ends of the separator to alongitudinally central position. The upper of the outlets is for thedischarge of the lightweight fraction of the well fluids, and the lowerof the outlets is for the discharge of the heavier fraction.

SUMMARY OF THE INVENTION

The present invention is at least partially based on the realisationthat, as long as the flow velocity is not too high, the stratificationthat often occurs between liquids of different density e.g. when beingcarried by a pipeline presents an opportunity for gravity-basedseparation of the more dense liquid. In particular, when the pipelinehas an upwardly inclined section in the direction of flow, the denserliquid slows down and its holdup does not change appreciably withchanges in the flow rate of the denser liquid itself. Its holdupdepends, rather, for a given pipeline inclination and for given physicalproperties of the liquids, on the flowrate of the less dense liquid.Effectively, the denser liquid forms a sump extending downstream (i.e.uphill) from the foot of the uphill section. If the denser liquid isextracted from the sump at a rate equal to its total flow rate into thepipeline, then the sump will tail off at some position on the uphillsection.

Thus, in general terms, the present invention provides (i) a flowseparator for separating two liquids of differing density, the separatorbeing adapted to provide a gravitationally stratified flow of theliquids such that an interface between the liquids is inclined from thehorizontal, and (ii) a method of separating two liquids of differingdensity comprising: providing a gravitationally stratified flow of theliquids such that an interface between the liquids is inclined from thehorizontal.

The inclined liquid/liquid interface defines an upper surface of a sumpformed by the second liquid. The inclination of the interface is incontrast with known in-line gravity separators, such as that describedin WO/02/01044, in which there is no stratified liquid flow such thatthe interface between separated hydrocarbon and water is horizontal.Indeed, the present invention facilitates true in-line separation in thesense that it does not require the retention of stagnant liquid in asettling chamber, but rather separation occurs while the liquids flow.

As to known cyclone separators, these may at some point produce aninterface between separated liquids which is inclined from thehorizontal, but the separation is of course produced by induced cyclonicmotion rather than by gravitation.

More particularly, in a first aspect the present invention provides anin-line flow separator comprising:

an uphill section of pipeline which, in use, carries a gravitationallystratified flow of a first liquid and a second denser liquid, wherebythe second liquid forms a sump extending uphill from the foot of theuphill section, and an interface between the first and second liquids onthe uphill section is inclined from the horizontal; and

an extraction port in the pipeline for extracting the second liquid fromthe sump.

The uphill section of pipeline has an angle of inclination to thehorizontal, and typically, e.g. under conditions of steady state flow,the interface between the first and second liquids on the uphill sectioninclines upwardly at substantially the same angle to the horizontal.

However, when the second liquid is extracted from the sump at a rateequal to its flow rate into the separator, the sump tails off at aposition on the uphill section. At the sump tail, the interface betweenthe first and second liquids is typically substantially horizontal.

The rate of extraction at the extraction port may be controlled by apump or a valve.

An advantage of the separator is that it can be easily retrofitted to apipeline that has a suitable inclined section.

The pipeline may be an oil pipeline, the first liquid being oil and thesecond liquid being water. The separator is typically installedabove-ground, and preferably is installed at a wellhead. However, thepresent invention is generally applicable to situations where stratifiedflow of two liquids with varying densities occurs. Thus, areas ofapplication of the invention include, but are not limited to, thepetrochemical, food, and paint industries.

Conveniently, the extraction port may be located immediately downstreamof the foot of the uphill section.

The extraction port may take the form of a pipe extending downwards fromthe underside of the pipeline, and having an upper portion with anenlarged cross-sectional area which produces a relatively low initialextraction flow velocity into the port, and a lower portion with anarrower cross-sectional area producing a subsequent higher extractionflow velocity. Thus, if a droplet of the first liquid is entrained inthe extracted second liquid, the droplet may still have an opportunityto escape back into the pipeline because, in the upper portion,gravitational forces may not be dominated by frictional forces, whereasthey are more likely to be thus-dominated in the narrower lower portion.

There may be more than one extraction port for extracting the secondliquid from the sump. By employing a plurality of ports, it is possibleto extract more liquid without disturbing the stratified flow in thepipeline.

Preferably the extraction port(s) do not reduce or obstruct thecross-sectional area of the pipeline. In this way, pressure losses anddisturbances to the stratified flow can be reduced or eliminated.

Indeed, more preferably, there are no significant obstructions orreductions in the cross-sectional area of the pipeline from one end ofthe separator to the other.

The length of a downstream tail of the sump and the thickness of thesump will be dependent on factors such as the pipeline diameter, thefirst and second liquid properties, the first liquid flow rate, and theangle of inclination of the uphill section. Typically (e.g. in oilpipeline applications), the angle of inclination of the uphill sectionto the horizontal is in the range from 2° to 6°. Consequently, theliquid/liquid interface on the uphill section (excluding at the sumptail with its typically horizontal liquid/liquid interface) generallyhas the same inclination to the horizontal. We have found thatinclinations beyond 6° can have an adverse effect on stratification.

Preferably, the separator further comprises means for characterising theflow rate of the second liquid into the uphill section,

whereby the rate of extraction of the second liquid at the extractionport can be controlled on the basis of the characterised flow rate ofthe second liquid.

Some embodiments of the present invention make use of the sump tail tocontrol the rate of extraction of the denser liquid.

Consequently, the means for characterising the flow rate of the secondliquid into the uphill section may be a sensor arrangement on the uphillsection for sensing the position of a downstream tail of the sump,whereby the rate of extraction of the second liquid at the extractionport can be controlled on the basis of the behaviour of the sump tail.

Thus, some embodiments provide a system for controlling sump flow in apipeline which, in use, carries a stratified flow of a first liquid anda second denser liquid, the system comprising:

a section of the pipeline in which the stratified flow is uphill,whereby the second liquid forms a sump extending downstream from thefoot of the uphill section;

an extraction port in the pipeline for extracting the second liquid fromthe sump, and

a sensor arrangement on the uphill section for sensing the position of adownstream tail of the sump, whereby the rate of extraction of thesecond liquid at the extraction port can be controlled on the basis ofthe behaviour of the sump tail.

For a given extraction rate, the sump tail moves downstream when extrasecond liquid enters the pipeline, and retreats when the second liquidbecomes deficient. Thus, if the sump tail travels too far from theextraction port, the operator knows that the rate of second liquidextraction should be increased, and if the sump tail moves too close tothe port, the operator knows that the rate of second liquid extractionshould be decreased. Furthermore, by maintaining the sump tail a safedistance from the extraction port, an operator can ensure thatsubstantially only the second liquid is extracted. Computer-basedcontrol means may be provided to automatically control the rate ofsecond liquid extraction e.g. on the basis of any one or combination ofthe position of the sump tail, the speed of movement of the tail and thedirection of movement of the tail.

Preferably, the length of that portion of the uphill section over whichthe position of the sump tail is sensed by the sensor arrangement is atleast a distance of 15D, and more preferably at least 20D, where D isthe internal diameter of the pipeline. The longer the uphill section,the more reliably the sump tail can be maintained in the section. If,for example, Q_(sl,i)>Q_(sl,e) (where the second liquid flow rate intothe pipeline is Q_(sl,i) and second liquid is extracted out of thepipeline at a rate Q_(sl,e)), the time it takes for the tail to movefrom the (most downstream) extraction port to the top of the uphillsection is (Q_(sl,I)−Q_(sl,I))/(SH_(sl)L), where S denotes the pipelineinternal cross-sectional area, L denotes the distance between the portto the top of the uphill section, and H_(sl) denotes the second liquidholdup (which is primarily governed by the first liquid flow rate, thepipeline inclination, and the pipeline internal diameter).

Basing the extraction of the second liquid from the sump on thebehaviour of the sump tail can be particularly advantageous with respectto separator control. The time scale of such a separator is typically ofthe order of seconds to minutes (depending on pipe diameters andlengths), which renders the separator amenable to control with verysimple parameters. Such a separator requires no measurement offlowrates, holdup, or properties, and it does not require repeatedcalibration of the instruments, the only measurement being the detectionof the downstream tail of the sump.

Conveniently, the sensor arrangement may comprise a plurality of sensorsspaced along the uphill section, the sensors determining the position ofthe sump tail on the basis of differing properties for the first andsecond liquids. These may be electronic sensors sensing electricalproperties. However, any sensors capable of detecting contrastingphysical or chemical properties may be used. For example, opticalsensors may be employed.

However, if electronic sensors are used, each sensor may comprise aspark plug, as manufactured for use in an internal combustion engine(ICE), each spark plug being arranged to perform electrical measurementsacross the wall of the pipeline. Spark plugs have electrical insulation,temperature and pressure ratings which in general are above the ratings(typically 100,000 V, 200° C., 34.47 MPa [5,000 psi]) required in theoil industry. They are also readily obtainable even in poorly developedcountries or remote oilfield environments, making spark plug-basedsensors simple and inexpensive to produce.

Alternatively, rather than making use of a sump tail to control the rateof extraction of the denser liquid, the means for characterising theflow rate of the second liquid may be a system for determining the cutof the second liquid entering the separator, whereby the rate ofextraction of the second liquid at the extraction port can be controlledon the basis of the determined second liquid cut. Again, computer-basedcontrol means may be provided to automatically control the rate ofsecond liquid extraction.

Suitable systems for determining liquid cuts are known to the skilledperson. Such a system should be included in the separator upstream ofthe extraction port. For example, if there is gas in the flow, amulti-phase flow meter, such as Schlumberger's Vx™ gamma-ray multi-phaseflow meter (see Society of Petroleum Engineers (SPE) papers 63118, 77405and 76766), may be used to determine the second liquid cut. However,simpler systems may be used if a gas diverter (see below) is used toremove gas from the pipeline before the liquid flow rate measurement ismade. Such a system may comprise a holdup meter for the second liquidcombined with a flowmeter for measuring the total liquid flow rate inthe pipeline, the cut of the second liquid being estimated by combiningthe two measurements. A Coriolis mass flow meter may be used effectivelyto measure the liquid flowrate(s) and second liquid cut. A microwave cutmeter for the second liquid may also be used in conjunction with aliquid flow meter such as an ultrasonic flowmeter.

In general, if a system for determining the cut of the second liquidentering the separator is used, rather than a sensor arrangement on theuphill section for sensing the position of a downstream tail of thesump, it is desirable for the separator to further comprise a flow meter(of known type) for measuring the flow rate of extracted second liquid.This allows the second liquid extraction rate to be matched to thesecond liquid inflow rate.

In some embodiments, one or more further separators are installed inseries downstream of the first separator. Each further separator has itsown uphill section and can be used to extract a proportion of the secondliquid flow. Thus a sump tail only forms on an uphill section if therate of water extraction from the respective extraction port equals thewater flow rate into that separator. Of course, in use, any separatordownstream of such a tail is redundant. Preferably the first separatorand each further separator has a flow meter for measuring the flow rateof second liquid extracted by the respective separator. In theseembodiments, for each separator downstream of the first separator, theflow rate of the second liquid into the respective uphill section can becharacterised by subtracting the total flow rate of second liquidextracted by the upstream separators from the flow rate of the secondliquid into the first separator.

The separator may comprise a gas diverter at a position upstream of theextraction port and/or upstream of the uphill section for removing gasfrom the pipeline. Many oil wells also produce significant amounts ofgas, and such a diverter may then be particularly advantageous as thepresent inventors have found that the separator can be poorly tolerantto gas in the pipeline. In particular, gas turbulence can destroy theinterface between the two liquids. With the implementation of gasdiversion, the separator effectively operates as a multi- or three-phaseseparator, each of the first and second liquids and the gas beingdefined as a “phase”.

In particular, the present inventors realised that gas in the pipelinecan be detrimental to the controlled extraction of the second liquidfrom the sump. That is, even in embodiments which do not make use of thesump tail to control the rate of extraction of the denser liquid, it isadvantageous to remove gas from the pipeline.

Typically the gas diverter removes substantially all the gas from thepipeline.

Preferably the gas diverter does not reduce or obstruct thecross-sectional area of the pipeline. In this way, pressure losses anddisturbances to the stratified flow can be reduced or eliminated.

Preferably, the gas diverter removes gas from the pipeline at a positionupstream of the uphill section. For example, the separator may furthercomprise a section of the pipeline in which the stratified flow isdownhill, the downhill section being upstream of the uphill section, andthe gas diverter removing gas from the pipeline on the downhill section.Because downhill sections promote stratification, even at very high flowrates, such an arrangement can significantly reduce turbulence at theposition where gas is removed. Thus liquid/gas interactions can beminimised, and the likelihood of liquid unintentionally being removed bythe gas diverter can be reduced.

The gas diverter may comprise a pipe extending substantially verticallyupwards from the upper side of the pipeline at the pipeline position atwhich gas is removed. This simple arrangement has been found to performwell under a range of operational conditions. It can be a completelypassive in the sense that, even under transient operating conditionswhen the amount of gas in the flow can vary significantly, no activecontrol systems have to be installed in order to divert gas efficientlythrough the pipe while avoiding liquid being carried over through thediverter as well. Preferably the pipe extends vertically to an elevationwhich is higher than the top of the uphill section. Indeed, in general,the pipe should extend vertically to an elevation which prevents liquidbeing carried over during transient operation.

Less desirably, more actively-controlled gas diverters may be used. Forexample, U.S. Pat. No. 5,589,642 describes a multi-phase fluid flowmeter which incorporates a gas flow path. Pressure sensors and acomputer determine when to open the path in response to substantial gasflows.

The diverted gas may be reintroduced into the pipeline downstream of theuphill section. For example, the gas diverter can be arranged to rejoindiverted gas to the pipeline downstream of the uphill section.Preferably, in such separators, the elevation of the pipeline positionat which the gas diverter rejoins diverted gas to the pipeline is lowerthan the elevation of the pipeline position at which the gas diverterremoves gas from the pipeline. This helps to ensure that liquid does notclimb into the diverter. Preferably the gas diverter rejoins divertedgas to the pipeline at a downhill section of the pipeline.

The diverter may comprise a gas flow meter (of known type) for measuringthe flow rate of diverted gas. Indeed, preferably, the separator thenalso includes a first liquid flow meter for measuring the flow rate offirst liquid in the pipeline after all the second liquid is extracted,and one or more second liquid flow meters for measuring the flow rate ofsecond liquid extracted at the respective extraction port(s). Such anarrangement allows the separator to function as a multi-phase meter.

Optionally, in embodiments which comprise a gas diverter, the means forcharacterising the flow rate of the second liquid into the uphillsection is not a sensor arrangement on the uphill section for sensingthe position of a downstream tail of the sump.

In a second aspect, the present invention provides a method of in-lineflow separation comprising:

carrying a gravitationally stratified flow of a first liquid and asecond denser liquid along an uphill section of pipeline, whereby thesecond liquid forms a sump extending uphill from the foot of the uphillsection, and an interface between the first and second liquids on theuphill section is inclined from the horizontal, and

extracting the second liquid from the sump.

Thus the method corresponds to the separator of the previous aspect, andany one or combination of the optional features of that separatorpertain also to the method of the second aspect.

For example, the method preferably further comprises characterising theflow rate of the second liquid into the uphill section, whereby the rateof extraction of the second liquid is controlled on the basis of thecharacterised flow rate of the second liquid.

More preferably, the characterisation of the flow rate of the secondliquid into the uphill section is performed by sensing the position, onthe uphill section, of a downstream tail of the sump, and the rate ofextraction of the second

Thus, some embodiments provide a method for controlling sump flow in apipeline comprising:

carrying a stratified flow of a first liquid and a second denser liquidalong the pipeline, the pipeline having a section in which thestratified flow is uphill, whereby the second liquid forms a sumpextending downstream from the foot of the uphill section,

sensing the position, on the uphill section, of a downstream tail of thesump, and

extracting the second liquid from the sump, the rate of extraction ofthe second liquid being controlled on the basis of the behaviour of thesump tail.

The method of the second aspect may further comprise removing gas fromthe pipeline at a position which is upstream of the position at whichthe second liquid is extracted from the sump and/or upstream of theuphill section. However, when gas is removed in this way, thecharacterisation of the flow rate of the second liquid into the uphillsection may exclude sensing the position, on the uphill section, of adownstream tail of the sump. Instead, for example, the characterisationof the flow rate of the second liquid into the uphill section can beperformed by determining the cut of the second liquid, the rate ofextraction of the second liquid at the extraction port being controlledon the basis of the determined second liquid cut.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the invention will now be described by way of examplewith reference to the accompanying drawings in which:

FIG. 1 shows schematically an oil pipeline;

FIG. 2 a shows schematically a further oil pipeline having a sump flowcontrol system according to a first embodiment of the present invention;

FIG. 2 b shows an enlarged view of the extraction port of the sump flowcontrol system of FIG. 2 a;

FIG. 3 shows schematically an electronic sensor based on an ICE sparkplug;

FIG. 4 shows schematically two further sensors based on ICE spark plugsmounted spaced apart in a wall of an oil pipe;

FIG. 5 shows schematically a further oil pipeline having an in-linethree-phase separator according to a second embodiment of the presentinvention;

FIG. 6 shows schematically a further oil pipeline having an in-linethree-phase separator according to a third embodiment of the presentinvention; and

FIG. 7 shows schematically a further oil pipeline having a series ofin-line separators according to a fourth embodiment of the presentinvention.

DETAILED DESCRIPTION

FIG. 1 shows schematically an oil pipeline 1 having an upwardly inclinedsection 2. A stratified flow of oil 3 and denser water 4 flows along thepipeline in the direction indicated.

When the stratified flow reaches the foot of the inclined section, thethickness of the water layer increases (i.e. the water holdupincreases), and maintains that thickness until it reaches the top of theincline. Thus the thickened water layer 5 is effectively a sump. As longas the flowrate of oil is below a certain limit the sump remains intactand is not entrained in the oil flow. Flowrates encountered in oilpipelines under normal conditions are generally below this limit.

FIG. 2 a shows a further oil pipeline, but now having a sump flowcontrol system according to a first embodiment of the present invention.Equivalent features have the same reference numbers in FIGS. 1 and 2 a.An extraction port 6 is positioned just above the foot of inclinedsection 2, and a series of spaced electronic sensors 7 a to 7 f aremounted to the underside (at or near the quadrant) of the pipeline anddetect the local presence of oil or water on the basis of the differentelectrical conductivities of oil and water. Of course, instead of asingle extraction port, the pipeline could have a plurality of ports.

The water flow rate into the pipeline is Q_(w,i) and water is extractedout of the pipeline through port 6 at a rate Q_(w,e). As Q_(w,i) andQ_(w,e) are approximately equal, a tail 8 forms on the sump 5 on theuphill section. If Q_(w,i) exceeds Q_(w,e), the tail progresses up theuphill section, whereas if Q_(w,e) exceeds Q_(w,i) the tail retreatsdownhill. The equilibrium (i.e. Q_(w,i)=Q_(w,e)) position of the tailand its length depend on several factors such as the pipeline diameter,the oil and water physical properties, the oil flow rate, and the angleof inclination of the uphill section.

In the situation shown in FIG. 2 a, the tail ends between sensors 7 cand 7 d. Therefore, sensors 7 a to 7 c measure a significantly higherelectrical conductivity than sensors 7 d to 7 f, allowing the positionof the tail to be located.

Furthermore, if Q_(w,i)≠Q_(w,e), then the tail will move at a rateproportional to ΔQ_(w)=Q_(w,i)−Q_(w,e). Clearly, the movement will bedownstream if ΔQ_(w) is positive and upstream if it is negative. Thusnot only can an operator ensure that the tail is situated at a “safe”distance from the extraction port and the top of the uphill section, butthe speed and direction of movement of the tail, as measured by thesensors, gives an indication of how to change the rate of extraction tomatch Q_(w,e) to Q_(w,i). Thus the water extraction rate is controlledon the basis of the behaviour of the sump tail on the uphill section.

Preferably, this control is automatically exercised by a computer-basedcontroller (not shown) which receives the conductivity measurements fromthe sensors and controls e.g. a pump or valve (not shown) at port 6 tovary the rate of extraction.

Preferably, also, a gas diverter (not shown) of known type or as any oneherein described is installed upstream of the pipeline of FIG. 2 a toremove any gas from the liquid flow. The diverted gas may bereintroduced into the pipeline downstream of the uphill section.

FIG. 2 b shows an enlarged view of extraction port 6. It has an upperportion 6 a opening to the pipeline with an enlarged cross-sectionalarea which produces a relatively low initial extraction flow velocityinto the port, and a lower portion 6 b with a narrower cross-sectionalarea producing a relatively high extraction flow velocity. Thus, if adroplet of oil is entrained in the extracted water, the droplet stillhas an opportunity to escape back into the pipeline because, in thewider upper portion, gravitational forces are not dominated byfrictional forces, as they are in the narrower lower portion.

Conveniently, the electronic sensors can be based on ICE spark plugs.FIG. 3 shows an ICE spark plug 11 mounted in a wall 12 of an oil pipe.The spark plug has a central electrode 13, a ceramic insulator 14 and asteel outer conductor body 15. The conventional side electrode 16 of theouter body has been shortened so that it and the adjacent end of thecentral electrode can support a sensing element 17 for sensing theresistivity/conductivity of the liquid flowing within the pipe.

An external electrical circuit 18 joins the central electrode and outerconductor body and they can thus be used to communicate electrical powerto the sensing element so that it can perform measurements.

FIG. 4 shows another form of the spark plug-based electronic sensor inwhich the side electrode of the spark plug has been entirely removed. InFIG. 4, two of these sensors are mounted spaced apart in a wall of anoil pipe. Equivalent features have the same reference numbers in FIGS. 3and 4.

The sensors of FIG. 4 are used to sense the position of the tail of thewater sump discussed above in relation to FIG. 2 a. When water ispresent (as at the left hand sensor), an electrical short occurs betweenthe central electrode and outer conductor body. Conversely, if there isonly oil in the pipe (as at the right hand sensor), the impedancebetween the central electrode and outer conductor body is effectivelyinfinite. Thus the presence of water and the position of the sump tailcan be detected by measuring the impedance between the central electrodeand outer conductor body.

FIG. 5 shows schematically a further oil pipeline having an in-linethree-phase separator according to a second embodiment of the presentinvention. Equivalent features have the same reference numbers in FIGS.1, 2 a and 5.

In this embodiment the separator has three T-junctions 20. Thesejunctions respectively form a gas extraction port and two spaced waterextraction ports. The gas extraction port is upstream of the waterextraction ports and upwardly inclined pipeline section 2, and feeds agas diverter line 21. The water extraction ports are on the upwardlyinclined pipeline section 2.

The production stream which enters the pipeline contains a gas/oil/waterfluid flow. Except on downhill sections, the oil and water in such flowstend not to stratify because of gas-induced turbulence. However, the gasfraction of the flow is diverted from the production stream at the firstT-junction 20 into the gas diverter line 21. The gas diverter is apassive system that needs no active control. The diverted gas can berouted away from the production stream for industrial usage or flaring,or it can rejoin the oil stream at a later stage.

With the gas removed, the remaining oil/water flow can stratify. Thewater fraction of the stratified flow forms a sump extending upstreamfrom the foot of pipeline section 2, and is extracted through the secondand third T-junctions 20. The amount of water extracted is determined byvalves 22 which in turn are controlled on the basis of the output of asensor arrangement (not shown) uphill of the second and thirdT-junctions 20. The sensor arrangement senses the position of thedownstream tail of the sump. In this way, the rate of water extractioncan be controlled so as to maintain the sump tail at a position on theupwardly inclined pipeline section 2 above the second and thirdT-junctions 20. The flow downstream of the sump tail is thereforesubstantially entirely oil.

The design and operation of the separator is simple and robust. It hasno parts which intrude into the fluid flow to alter or obstruct thepipeline cross-section, no moving parts and uses little energy inoperation. The T-junctions (which have the same internal bore dimensionsas the main pipeline) cause very little pressure drop in the fluid flow.

FIG. 6 shows schematically a further oil pipeline having an in-linethree-phase separator according to a third embodiment of the presentinvention. Equivalent features have the same reference numbers in FIGS.1, 2 a, 5 and 6.

The well production stream contains gas, oil and water and enters theseparator at a downhill section 33 of pipeline. A gas diverter 31comprising a substantially vertically extending pipe 32 connects to thepipeline at the upperside thereof at position P_(g1) on the downhillsection, whereby the gas is diverted up pipe 32. Because the flow isdownhill, the oil and water tend to stratify in the downhill sectioneven though gas is present upstream of position P_(g1).

Uphill pipeline section 2 follows downhill section 33, and the waterfraction of the still-stratified flow forms a sump extending downstreamfrom the foot of the uphill section, and is extracted through extractionport 6. The amount of water extracted is determined by valve 22 which inturn is controlled on the basis of the measured water cut in theproduction stream. This water cut measurement can be made by amulti-phase flow meter, such as Schlumberger's Vx™ gamma-ray multi-phaseflow meter if the measurement is taken upstream of the pipe 32, or asimpler water cut measuring system may be used if the system isinstalled between pipe 32 and uphill section 2 as the system does notthen have to account for gas flows. Alternatively, a sensor arrangementcan be installed on the uphill section to measure the position of thedownstream tail of the sump, and the amount of water extracted can becontrolled on the basis of that position. In any event, the flowimmediately downstream of the sump is substantially entirely oil.

Particularly on uphill sections, gas can disturb the stratified oil andwater flow and therefore increase the risk of oil being entrained in theextracted water. However, by diverting the gas fraction on the downhillsection before the uphill section this problem can be avoided.

The height, H_(gas), of vertically extending pipe 32 can be determinedwith regard to the following considerations:

-   -   When the separator is full of liquid, but without any flow, then        the height of the liquid column inside the gas diverter line        will be equal to H_(Liquid), i.e. the height of the highest        point in the pipeline downstream of P_(g1). For example, if, as        shown in FIG. 6, the highest point is top of the uphill section,        then the height of the liquid column in pipe 32 when there is no        flow will be to equal the difference in elevation between P_(g1)        and the top of the uphill section. Of course, if there is a        check valve on the pipeline between the junction and the highest        point in the pipeline downstream of P_(g1), then H_(Liquid) is        the height of the highest downstream point in the pipeline        before the check valve.    -   When flow is initiated through the separator, the liquid flowing        in the pipeline encounters a pressure drop due to pipe wall        friction, interfacial friction between the phases, and pressure        losses due to fittings. The total pressure drop along the        pipeline from P_(g1) to the highest point in the pipeline (or to        the highest point between a check valve and the junction) causes        the liquid in pipe 32 to rise by an amount H_(ΔP)=ΔP/(ρg), where        ΔP is the pressure loss due to the fluid flow, ρ is the average        fluid density in the pipeline, and g is acceleration due to        gravity.    -   If initially there is no gas flow through the gas diverter,        either because it is closed or because there is no gas flowing        through the separator (for example as a result of a gas knockout        system upstream of the separator), then there will be a liquid        column in pipe 32. However, when gas is introduced into the        separator and the gas diverter is open, there is a transient        stage where gas forces its way up pipe 32 through the liquid        column. This results in both gas and liquid climbing pipe 32 as        a two-phase foam-like mixture. The vertical distance, H_(foam),        of such climb can be determined analytically and/or        experimentally but is likely to be greater than H_(Liquid).

Thus, in view of the factors discussed above, the vertical extension ofpipe 32 is preferably >H_(Liquid), more preferably >H_(Liquid)+H_(ΔP),and most preferably >+H_(ΔP)+H_(foam).

As shown in FIG. 6, pipe 32 branches off the pipeline at downhillsection 33. This helps significantly in reducing the turbulence atposition P_(g1) because flow in downhill sections tends to be completelystratified even at very high gas flowrates. In this way liquid/gasinteraction at P_(g1) can be reduced.

Particularly during transient operation, there can be a tendency forliquid to climb up pipe 32. To encourage this liquid to run back downpipe 32, it might be thought that pipe 32 should be inclined from thevertical, as the gas which is also trying to climb the pipe should thenbe able to pass over the returning liquid rather than having to push itsway through a liquid “plug”. That is, in an inclined pipe the gas andreturning liquid can stratify. However, the present inventors found thatthe amount of inclination needed to stratify the gas and returningliquid is so great as to be impractical to implement. Thus, the simplevertical configuration has been found most practical.

At the top of pipe 32, the gas diverter continues as a near horizontalpipe 34. However, inclining pipe 34 uphill by a few degrees, θ, allowsany liquid that is carried over with the gas, especially during initialtransient phases, to fall back into the pipeline via pipe 32.

It appears that the pipe diameter of the gas diverter is notparticularly significant. The present inventors have successfullytrialled a 2-inch (51 mm) pipe diameter, and this should be adequate formost oilfield pipeline applications. Pressure drop calculations suggestthat even 1-inch (25 mm) diameter pipe will suffice in many scenarios.

The gas diverter can be used to divert the gas away from the extractionand control zone of the separator and then to rejoin the diverted gas tothe oil flowing downstream from the water extraction zone. A diverteradapted for such operation is shown schematically in FIG. 6 by thedashed lines which extend the gas diverter pipework to rejoin the oilstream at point P_(g2). P_(g2) is on downhill section 35 of the pipelinedownstream of the uphill section. In downhill flow, liquid and gasremain stratified even at very high flow rates of each fluid. So on adownhill section it is relatively easy for gas to re-enter a pipelinecarrying a liquid stream, whereas the same may not be the case for gasre-entry to uphill liquid flow. The elevation of point P_(g2) is lowerthan the elevation of point P_(g1) to ensure that liquid will not climbup in the gas diverter vertical pipe.

Alternatively, as conditions or requirements demand, the gas can berouted elsewhere and not rejoined to the oil stream.

The gas diverter can be equipped with a control valve in case theoperator wishes to isolate the gas diverter line. However, without sucha valve, the gas diverter shown in FIG. 6 is a completely passivesystem.

The separator can also incorporate a number of flow meters, namely: agas flow meter for measuring the flow rate of gas removed by the gasdiverter 31 can be located at position A; an oil flow meter formeasuring the flow rate of the oil which remains in the pipeline can belocated at position B; and a water flow meter for measuring the flowrate of extracted water can be located at position C. These meters,which can be simple single phase flow meters of known type,advantageously allow the separator to function as a multi-phase flowmeter.

FIG. 7 shows schematically a further oil pipeline having a series ofin-line separators according to a fourth embodiment of the presentinvention. The pipeline carries a stratified oil and water flow.

Each separator has a respective uphill section 2. Upstream of its uphillsection, the first separator has a conventional water cut measuringdevice 40 for measuring the flow rate of water into the first separator.A gas diverter (not shown) may be fitted upstream of the water cutmeasuring device 40 if the fluid flow contains gas.

Water sumps extend up each uphill section and respective extractionports extract proportions of the total water flow from these sumps. Thewater extraction rate at each port is measured by a respective waterflow meter 41. A computer-based control system 42 receives water flowrate measurement signals from the water cut measuring device 40 and thewater flow meters 41 and controls valves 22 at each port in such a waythat the rate of extraction at each port does not risk oil beingextracted with the water. The control system can determine the waterflow rate into the second separator by subtracting the extraction ratefrom the first separator from the flow rate measured by water cutmeasuring device 4. Similarly, the control system can determine thewater flow rate into the third separator by subtracting the extractionrate from the first and second separators from the flow rate measured bywater cut measuring device 4.

While the invention has been described in conjunction with the exemplaryembodiments described above, many equivalent modifications andvariations will be apparent to those skilled in the art when given thisdisclosure. Accordingly, the exemplary embodiments of the invention setforth above are considered to be illustrative and not limiting. Variouschanges to the described embodiments may be made without departing fromthe spirit and scope of the invention.

1. A method of in-line flow separation comprising: carrying agravitationally stratified flow of a first liquid and a second denserliquid along an uphill section of pipeline, whereby the second liquidforms a sump extending uphill from the foot of the uphill section, andan interface between the first and second liquids on the uphill sectionis inclined from the horizontal, and extracting the second liquid fromthe sump.
 2. A method according to claim 17 further comprisingcharacterising the flow rate of the second liquid into the uphillsection, the rate of extraction of the second liquid being controlled onthe basis of the characterised flow rate of the second liquid.
 3. Amethod according to claim 17, wherein the pipeline is an oil pipeline,the first liquid being oil and the second liquid being water.
 4. Amethod according to claim 17, wherein the angle of inclination of theuphill section to the horizontal is in the range from 2° to 6°.
 5. Amethod according to claim 17, wherein the characterisation of the flowrate of the second liquid into the uphill section is performed bysensing the position, on the uphill section, of a downstream tail of thesump, and the rate of extraction of the second liquid at the extractionport is controlled on the basis of the behaviour of the sump tail.
 6. Amethod according to claim 21, wherein the length of that portion of theuphill section over which the position of the sump tail is sensed by thesensor arrangement is at least a distance of 15D, where D is theinternal diameter of the pipeline.
 7. A method according to claim 21,wherein the position of the sump tail is sensed using a plurality ofsensors spaced along the uphill section, the sensors determining theposition of the sump tail on the basis of differing properties for thefirst and second liquids.
 8. A method according to claim 23, whereineach sensor is an electronic sensor comprising a spark plug, asmanufactured for use in an internal combustion engine, the spark plugperforming electrical measurements across the wall of the pipeline.
 9. Amethod according to claim 17, wherein the characterisation of the flowrate of the second liquid into the uphill section is performed bydetermining the cut of the second liquid, and the rate of extraction ofthe second liquid at the extraction port is controlled on the basis ofthe determined second liquid cut.
 10. A method according to claim 25,further comprising the step of measuring the flow rate of second liquidextracted at the extraction port.
 11. A method according to claim 17,further comprising removing gas from the pipeline at a position which isupstream of the position at which the second liquid is extracted fromthe sump.
 12. A method according to claim 27, further comprisingcarrying the stratified flow in a downhill section of the pipeline whichis upstream of the uphill section, gas being removed from the pipelineon the downhill section.
 13. A method according to claim 27, wherein thegas is removed by a gas diverter comprising a pipe extendingsubstantially vertically upwards from the upper side of the pipeline.14. A method according to claim 27, further comprising rejoining removedgas to the pipeline downstream of the uphill section.
 15. A methodaccording to claim 30, wherein the elevation of the pipeline position atwhich gas rejoins the pipeline is lower than the elevation of thepipeline position at which gas is removed from the pipeline.